Hydrocarbon-containing gas, known generally as natural gas, is produced from natural gas wells, oil wells or hydrocarbon refining processes. Natural gas contains a number of combustible hydrocarbon and non-combustible inorganic constituents which have a broad range of molecular weights and boiling points. Natural gas constituents are normally in a gaseous state at atmospheric conditions of temperature and pressure. However, temperature and pressure vary widely from atmospheric conditions when storing or transporting natural gas causing the heavier, higher boiling point hydrocarbons to condense from the gas to a liquid state. Many problems accompany the handling of the resulting two-phase composition. Condensed natural gas liquids, which impede flow by accumulating in pipelines and attendant equipment, are a primary problem.
Handling of natural gas is simplified, if the lighter gases are separated from the readily condensable, heavier hydrocarbons so that the heavier hydrocarbons may be stored or transported separately in a liquid state, i.e. as natural gas liquids. Separation of the natural gas liquids from the lighter gases also enhances the marketability of specific natural gas products.
A number of processes have been described in the art for separating the lighter gaseous constituents from the heavier, higher boiling point hydrocarbons in a natural gas feed. A conventional means for separating the natural gas constituents is to pass the gas through an absorption tower wherein the higher boiling point hydrocarbons are stripped from the gas stream upon contact with a liquid absorbant. Such methods are often more effective when operated cryogenically. U.S. Pat. Nos. 4,318,723 to Holmes et al, 4,157,904 to Campbell et al, 3,359,743 to DiNapoli and 3,846,993 to Bates all describe cryogenic separation processes whereby the temperature of a natural gas is reduced either by rapid expansion or heat exchange. The resulting condensed liquids are separated from the gas in a cryogenic column.
U.S. Pat. Nos. 4,285,708 to Politte et al and 4,128,410 to Bacon and Gulby, J. G., "Options for Ethane Rejection in the Cryogenic Expander Plant," preprint 58th Annual GPA Conv. March 1979, teach cryogenic processes, which reduce the amount of ethane in condensed natural gas liquid to minimize the vapor pressure of the liquid. Bacon and Politte et al are staged processes. Bacon cools the gas by heat exchange with a refrigerant to condense the higher boiling point hydrocarbons. The cooled stream is fed to a separator where the uncondensed gas is removed as pipeline gas. The condensed hydrocarbons are fed to a fractionating tower to remove ethane from the condensate before recovering the condensate as liquid product. Politte et al deethanizes a natural gas feed by splitting it and feeding one stream directly to a deethanizer while feeding the other stream to a stabilizer to remove the heavier components as liquids. The overhead vapor from the stabilizer is fed to the deethanizer to complete the separation of liquids and gases therein.
Non-cryogenic processes for separating readily condensable, heavier, higher boiling point hydrocarbons from a natural gas feed generally do not produce a sufficiently devolatilized natural gas liquid. The vapor pressure of the natural gas liquid is too high to safely store or transport the liquid by conventional means. The above-cited cryogenic processes more effectively separate the gases and liquids in a natural gas feed to produce a less volatile liquid. However, the substantial additional cost of cryogenically designed equipment and energy required to operate the equipment offset the advantage of these cryogenic processes.
A process is needed to separate the heavier natural gas liquids from the lighter gases in a natural gas feed. More specifically, a process is needed, which sufficiently reduces the vapor pressure of the natural gas liquid by removing a portion of the ethane therefrom to allow safe handling of the liquid.